Offshore or subsea hydrocarbon deposits continue to attract significant attention from oil and gas producers throughout the world. As onshore hydrocarbon deposits currently in production, particularly in the United States, are depleted and as larger onshore oilfields are discovered only infrequently, producers increasingly look for new exploration and production opportunities in offshore locations.
A factor limiting the development of many of the discovered offshore hydrocarbon deposits, particularly crude oil, natural gas, and associated natural gas liquids, is the cost to install and maintain equipment and facilities to produce the hydrocarbons. Offshore drilling and production platforms and subsea production equipment installations require sizeable investments. In trying to maximize the economic benefits from offshore facilities, producers focus on reducing the installation weight and costs of the equipment on the offshore production platforms necessary to produce the hydrocarbons.
By reducing the installation weight and costs of equipment, new offshore installations may be smaller and less expensive for producing newly discovered fields and existing offshore installations may be further modified to handle the production from more wells and larger production areas. By using existing facilities, a production facility may exploit marginal reservoirs adjacent to or near existing fields. Also, by using existing facilities to produce new or marginal discoveries, an oil producer can extend the life of the facilities and increase the level of recoverable reserves at costs less than those required for new discoveries and new installations. Often such new or marginal discoveries may be located at a remote location, e.g. 5 to 15 miles (8 to 24 km), from existing production platforms or facilities. Large, lengthy flowlines are installed to transport produced wellbore fluids, primarily crude oil, natural gas, natural gas liquids, and water, to these platforms or facilities from such a remote location.
Although large, lengthy flowlines are significantly less expensive that new offshore production platforms, such flowlines may limit the fluid production rate from a given well. One of the more significant factors limiting the amount of fluid a given oil or gas well may produce is the amount of back pressure exerted at the wellhead by facilities downstream of the wellhead. One measure of the amount of such back pressure is referred to as the wellhead flowing pressure. The wellhead flowing pressure is typically the pressure at the wellhead during normal operating conditions without a wellhead choke or other flow restriction means in the wellhead. When the wellhead flowing pressure can be reduced, a typical well can produce more fluid from a given reservoir, which leads to a longer field production life and more oil and gas recovery.
Several factors can cause increases in wellhead flowing pressure in a given well. For example, flowlines from subsea wellheads to separation facilities may in some cases be several miles long which can result in significant friction losses caused by the turbulent, multiphase fluid flow in the flowlines. Such friction losses result in an increase in pressure required to move a given amount of fluid through a flowline. This pressure increase, when added to the operating pressures of facilities downstream of the wellhead, may significantly increase the wellhead flowing pressure. Another factor that causes increases in wellhead flowing pressure are changes in elevation from deepwater subsea fields to shallow water facilities. (Such changes in elevation cause an increased fluid head, i.e. a column of fluid, in a flowline which increases the wellhead flowing pressure and significantly reduces fluid production.) Still another factor that may increase the wellhead flowing pressure is the gas-liquid (two-phase) flow regime in the flowline to the production platform. Such two-phase flow results in increased pressure losses compared to single phase flow in a flowline, such as where gases are produced through one flowline and liquids (oil and water) are produced through another flowline. A separate, but related, problem may occur in a two-phase flow when large volumes of liquids accumulate in a flowline and upon accumulation of adequate pressure, are pushed forward and produced in a very short period of time as large slugs of liquids. Liquids produced during a slugging event can overwhelm the fluid handling capabilities of equipment employed on an offshore platform or facility as well as create high back pressures on a well.
Several efforts have been proposed and implemented to reduce the wellhead flowing pressure by separating produced wellbore fluids into gas and liquid streams at a subsea location and then providing separate flowlines to the platform or facilities for both the gas and liquid phase streams. One particularly innovative approach to separating wellbore fluids into gas and liquid phase streams at a subsea location is the vertical annular separation and pumping system (VASPS), as disclosed in U.S. Pat. No. 4,900,433, entitled “Vertical Oil Separator”, assigned to The British Petroleum Company. U.S. Pat. No. 4,900,433 is hereby incorporated by reference in its entirety. A more detailed description of a VASPS is provided in “VASPS: An Innovative Subsea Separation System” presented at the 11th International Conference and Exhibition, Oct. 19-21, 1999 at Stavanger, Norway, which presentation is hereby incorporated by reference in its entirety. A VASPS unit relates generally to the technical areas of subsea multiphase boosting systems and artificial lifting methods for increasing reservoir production rates.
A VASPS is a two-phase (gas-liquid) separation and pumping system which may be installed in a subsea “dummy well” near the mudline of the subsea floor. A “dummy well” is a simple borehole, typically lined with a casing or similar pipe structure, extending into the subsea surface near the mudline a distance adequate to receive the VASPS. VASPS receives a full wellbore fluid stream and separates the stream into a gas phase stream and a liquid phase stream. The gas phase stream is then directed to a flowline and transported to other facilities for additional treating, while the liquid phase stream is pumped from the VASPS through a separate flowline to other treating facilities. Such subsea separation provides several benefits, including primary gas phase-liquid phase separation at a subsea location, which reduces the need for large, weighty separators on the offshore platforms to handle a gas-liquid flow regime and lessens “slugging” effects associated with such gas-liquid two-phase flow.
A typical VASPS unit includes an outer pressure housing, an inner helix separator assembly, a gas discharge annulus, a centrally located liquid discharge tube, a liquid discharge pump, and an electric motor to drive the liquid discharge pump. The entire VASPS unit would then be placed in an outer casing that may be cemented in the dummy well in the seabed. Alternatively, a VASPS unit may be placed in an outer housing mounted in a support placed on or near the subsea mudline.
During operation of a VASPS unit, a multiphase well stream (typically consisting of crude oil, natural gas, natural gas liquids, and salt water) enters the outer pressure housing and is directed to the inner helix separator for primary separation of the gas and liquid phase streams. This primary separation is accomplished through the application of centrifugal forces created by the cylindrical shape of the helix. Separated gas flows through holes in the helix into a gas discharge annulus and up into a gas expansion chamber. The gas then exits the VASPS unit into a separate flowline for delivery to and further treatment at the production facility (typically the offshore platform). Meanwhile, the degassed liquid flows in a counter-current direction from the exiting gas down the helix separator into a liquid sump area where it is pumped by the liquid discharge pump through the central liquid discharge tube into a separate flowline for delivery to and further treatment at the production facility (again typically the offshore platform).
Two of the key components for the removal of produced liquids from a VASPS unit are the electric motor and the liquid discharge pump. The electric motor is frequently combined with the liquid discharge pump to form an integrated unit referred to as an “electrical submersible pump” (ESP). ESPs are typically controlled and powered through an umbilical cord in communication with a remote control system and power source. The ESP discharges the produced, separated liquids through the liquid discharge tubing.
ESPs have long been used to produce liquid from wellbores, typically from formations having little or no produced gas. ESPs generally have difficulty (and are not particularly effective) in pumping fluids with significant volumes of free gas as the centrifugal impellers of an ESP are typically designed for pumping fluids rather than compressing gas. Hence, with gases separated from wellbore fluids in a VASPS unit, an ESP can operate more effectively and efficiently to remove liquids. ESPs are supplied by various oilfield equipment suppliers, including Schlumberger with its REDA® line of ESPs and Baker Hughes with its Centrilift® line of ESPs. In many installations, ESPs are positioned in wellbores so that the electric motor is mounted below the pump (including the pump intake and discharge outlets). In a typical installation in a vertical or near vertical well, an ESP is set below the well perforations to maximize liquid draw down and to minimize gas introduction into and interference with the pump.
During operation, an ESP's electric motor can produce significant amounts of heat. As ESPs have no separate, dedicated cooling system to remove heat generated during normal operations, ESPs are designed to use wellbore fluids as a cooling medium to keep the pump and the electric motor from overheating. In many ESP arrangements, the pump is mounted above the electrical motor. In such arrangements, a device referred to as a pump shroud is sometimes used to direct the wellbore fluids around the electric motor during operation and to remove heat generated during pump operation. Without such a pump shroud or other fluid directing device, wellbore fluid would not move past the electrical motor and therefore not remove any significant heat generated by the electrical motor. A pump shroud typically covers and encloses the pump inlet above the top of the electric motor and may be 75 to 100 feet (25 to 30 meters) long. The wellbore liquid flows along the outside of the pump shroud to the bottom of the ESP. The liquid then makes a 180-degree turn at the bottom of the pump shroud and then flows upward between the inside of the pump shroud and the electric motor, removing heat generated by the electric motor as the wellbore fluid moves past the motor and into the pump. The pump shroud is typically retrieved when the ESP is removed from the wellbore.
In some wellbores with ESP installations, as well as in wellbores using a VASPS unit, installed pump shrouds may create numerous problems and limitations to the operations of the ESP. An improperly mounted or damaged pump shroud can create multiple problems, such as misdirected fluid flow, which can lead to electric motor overheating, which can in turn lead to excessive scale build-up between the electric motor and the pump shroud, which can further lead to reduced fluid production due to scale build-up; poor gas separation due to pump shroud leakage; overheating of the electric pump causing shortened ESP run-times between repairs; and excessive pump shroud vibrations. Additionally, a pump shroud reduces the size of an ESP that can be placed in a given wellbore. If the pump shroud could be removed and replaced by a design that would provide the necessary wellbore fluid flow for adequate cooling of the ESP motor, larger ESPs, capable of moving more wellbore fluids, could be installed in a given opening. A more detailed description of a VASPS unit is provided below.